FIRSTENERGY CORP - FORM 8-K - EX-99.1 - EXHIBIT - ME FINANCIALS

Attached files

file	filename
8-K - 8-K - FIRSTENERGY CORP	a8-kdated6514.htm
EX-99.2 - EXHIBIT - PN FINANCIALS - FIRSTENERGY CORP	exhibit992-pnfinancialstat.htm

METROPOLITAN EDISON COMPANY

UNAUDITED INTERIM FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2014 AND 2013

GLOSSARY OF TERMS

The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries.



AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011. As of January 1, 2014, AE merged with and into FirstEnergy Corp.
FE	FirstEnergy Corp., a public utility holding company
FES	FirstEnergy Solutions Corp., which provides energy-related products and services
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
ME	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	ME, PN, Penn and WP
PN	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary

The following abbreviations and acronyms are used to identify frequently used terms in this report.
AFS	Available-for-sale
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income
DSP	Default Service Plan
EDC	Electric Distribution Company
EE&C	Energy Efficiency and Conservation
EGS	Electric Generation Supplier
EPA	United States Environmental Protection Agency
ERO	Electric Reliability Organization
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting Principles Generally Accepted in the United States of America
ICE	IntercontinentalExchange, Inc.
kV	Kilovolt
LOC	Letter of Credit
LSE	Load Serving Entity
MISO	Midcontinent Independent System Operator, Inc.
MLP	Master Limited Partnership
Moody’s	Moody’s Investors Service, Inc.
MWH	Megawatt-hour
NDT	Nuclear Decommissioning Trust
NERC	North American Electric Reliability Corporation
NITS	Network Integration Transmission System
NOV	Notice of Violation
NSR	New Source Review
NUG	Non-Utility Generation
NYISO	New York Independent System Operator
OCA	Office of Consumer Advocate
OPEB	Other Post-Employment Benefits
PCRB	Pollution Control Revenue Bond
Pennsylvania Industrials	ME Industrial Users Group and PN Industrial Customer Alliance
PJM	PJM Interconnection LLC
PPUC	Pennsylvania Public Utility Commission
PURPA	Public Utility Regulatory Policies Act of 1978

GLOSSARY OF TERMS, Continued

RFC	ReliabilityFirst Corporation
RFP	Request for Proposal
RTEP	Regional Transmission Expansion Plan
S&P	Standard & Poor’s Ratings Service
SERTP	Southeastern Regional Transmission Planning
SMIP	Smart Meter Implementation Plan
SREC	Solar Renewable Energy Credit
TSC	Transmission Service Charge
U.S. Court of Appeals for the D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
VIE	Variable Interest Entity

METROPOLITAN EDISON COMPANY

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended March 31
(In thousands)	2014			2013
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	217,161		$	218,268
Gross receipts tax collections	11,746			12,330
Total revenues	228,907			230,598

OPERATING EXPENSES:
Purchased power	61,171			38,115
Purchased power from non-affiliates	58,000			64,234
Other operating expenses	51,934			31,140
Provision for depreciation	13,315			12,819
Amortization (deferral) of regulatory assets, net	(20,492		)	20,116
General taxes	14,343			14,760
Total operating expenses	178,271			181,184

OPERATING INCOME	50,636			49,414

OTHER INCOME (EXPENSE):
Miscellaneous income	1,067			821
Interest expense	(13,936		)	(13,096		)
Capitalized interest	276			69
Total other expense	(12,593		)	(12,206		)

INCOME BEFORE INCOME TAXES	38,043			37,208

INCOME TAXES	15,357			15,263

NET INCOME	$	22,686		$	21,945

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	22,686		$	21,945

OTHER COMPREHENSIVE LOSS
Pensions and OPEB prior service costs	(3,464		)	(4,400		)
Amortized losses on derivative hedges	50			84
Other comprehensive loss	(3,414		)	(4,316		)
Income tax benefits on other comprehensive loss	(1,417		)	(1,791		)
Other comprehensive loss, net of tax	(1,997		)	(2,525		)

COMPREHENSIVE INCOME	$	20,689		$	19,420

The accompanying Notes to Financial Statements are an integral part of these financial statements.

METROPOLITAN EDISON COMPANY

BALANCE SHEETS

(Unaudited)



(In thousands, except share amounts)	March 31, 2014			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	158		$	157
Receivables-
Customers, net of allowance for uncollectible accounts of $7,408 in 2014 and $7,041 in 2013	158,947			140,386
Affiliated companies	42,691			23,419
Other	15,880			17,252
Prepaid taxes	20,635			5,932
Accumulated deferred income taxes	9,226			12,493
Other	1,795			2,827
	249,332			202,466
UTILITY PLANT:
In service	2,732,629			2,710,676
Less — Accumulated provision for depreciation	963,892			952,242
	1,768,737			1,758,434
Construction work in progress	47,501			44,034
	1,816,238			1,802,468
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts	328,859			322,227
Other	854			849
	329,713			323,076
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	416,499			416,499
Regulatory assets	147,456			140,827
Other	15,954			15,253
	579,909			572,579
	$	2,975,192		$	2,900,589
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	182,491		$	181,470
Short-term borrowings
Affiliated companies	61,845			23,281
Other	75,000			50,000
Accounts payable-
Affiliated companies	50,478			42,111
Other	55,449			37,035
Accrued taxes	10,028			25,942
Accrued interest	8,982			15,546
Other	41,783			48,579
	486,056			423,964
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares -740,905 shares outstanding	827,856			827,733
Accumulated other comprehensive income	12,150			14,147
Accumulated deficit	(21,171		)	(43,857		)
Total common stockholder's equity	818,835			798,023
Long-term debt and other long-term obligations	617,841			619,546
	1,436,676			1,417,569
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	576,995			577,214
Accumulated deferred investment tax credits	5,522			5,603
Nuclear fuel disposal costs	44,538			44,531
Asset retirement obligations	239,181			235,224
Retirement benefits	72,436			74,252
Power purchase contract liability	21,752			27,913
Other	92,036			94,319
	1,052,460			1,059,056
COMMITMENTS AND CONTINGENCIES (NOTE 8)
	$	2,975,192		$	2,900,589

The accompanying Notes to Financial Statements are an integral part of these financial statements.

METROPOLITAN EDISON COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended March 31
(In thousands)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	22,686		$	21,945
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	13,315			12,819
Amortization (deferral) of other regulatory assets, net	(20,492		)	20,116
Deferred purchased power and other costs, net	4,171			(1,774		)
Deferred income taxes and investment tax credits, net	(234		)	2,406
Change in current assets and liabilities
Receivables	(36,461		)	(8,790		)
Prepayments and other current assets	(13,958		)	(20,198		)
Accounts payable	30,727			28,641
Accrued taxes	(15,914		)	7,397
Accrued interest	(6,564		)	(4,308		)
Retirement benefits	(5,290		)	(8,400		)
Cash collateral	(5,291		)	(10,735		)
Other	3,276			3,910
Net cash provided from (used for) operating activities	(30,029		)	43,029

CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	—			300,000
Short-term borrowings, net	63,564			—
Redemptions and repayments-
Long-term debt	—			(150,000		)
Short-term borrowings, net	—			(127,717		)
Return of capital payments	—			(30,000		)
Other	(7		)	(2,501		)
Net cash provided from (used for) financing activities	63,557			(10,218		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(28,104		)	(28,692		)
Sales of investment securities held in trusts	54,213			56,785
Purchases of investment securities held in trusts	(57,316		)	(59,868		)
Asset removal costs	(2,348		)	(1,019		)
Other	28			(17		)
Net cash used for investing activities	(33,527		)	(32,811		)

Net change in cash and cash equivalents	1			—
Cash and cash equivalents at beginning of period	157			157
Cash and cash equivalents at end of period	$	158		$	157

The accompanying Notes to Financial Statements are an integral part of these financial statements.

METROPOLITAN EDISON COMPANY

NOTES TO FINANCIAL STATEMENTS

(Unaudited)



Note Number		Page Number
1	Organization and Basis of Presentation	8
2	Accumulated Other Comprehensive Income	8
3	Pensions and Other Postemployment Benefits	8
4	Taxes	8
5	Fair Value Measurements	8
6	Derivative Instruments	11
7	Regulatory Matters	11
8	Commitments and Contingencies	14

1. ORGANIZATION AND BASIS OF PRESENTATION

ME is a wholly owned subsidiary of FE, and is incorporated in Pennsylvania. ME operates an electric transmission and distribution system in Pennsylvania. ME is subject to regulation by the PPUC and the FERC.

Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted. These interim financial statements should be read in conjunction with the financial statements and notes included in ME's audited financial statements for the year ended December 31, 2013.

The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. ME has evaluated events and transactions for potential recognition or disclosure through May 20, 2014, the issuance date of the financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

New accounting pronouncements not yet effective are not expected to have a material effect on ME's financial statements.

2. ACCUMULATED OTHER COMPREHENSIVE INCOME

AOCI reclassifications of defined benefit pension and OPEB plan prior service costs into the computation of net periodic benefit costs (credits) (see Note 3 Pension and Other Postemployment Benefits for additional details) were $3 million and $4 million (pre-tax) during the three months ended March 31, 2014 and 2013.

3. PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

ME's net periodic pension and OPEB credits (including amounts capitalized) were as follows:



For the Three Months Ended March 31,	2014			2013
	(In millions)
Pensions	$	(1	)	$	(2	)
OPEB	$	(3	)	$	(4	)

The net periodic pension and OPEB credits (net of amounts capitalized) recognized in earnings by ME were as follows:



For the Three Months Ended March 31,	2014			2013
	(In millions)
Pensions	$	(1	)	$	(1	)
OPEB	$	(2	)	$	(3	)

4. TAXES

ME’s interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items.

ME’s effective tax rate from continuing operations for the three months ended March 31, 2014 and 2013 was 40.4% and 41.0%, respectively.

For federal income tax purposes, ME files as a member of the FE consolidated group. In April 2014, the Internal Revenue Service completed its examination of FE’s 2011 and 2012 federal income tax returns.

5. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques for Level 2 and Level 3 are as follows:

Level 1 - Quoted prices for identical instruments in active markets.

Level 2 - Quoted prices for similar instruments in active markets;

- Quoted prices for identical or similar instruments in markets that are not active

- Model-derived valuations for which all significant inputs are observable market data.

Level 3 - Valuation inputs are unobservable and significant to the fair value measurement.

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by FE's Risk Policy Committee (see Note 6, Derivative Instruments of these Notes to Financial Statements (Unaudited)), are used to measure fair value. A more detailed description of ME's valuation process for NUG contracts is as follows:

NUG contracts represent purchased power agreements with third-party NUGs that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value using a mark-to-model methodology on a quarterly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWHs. Pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.

ME primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, ME maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2014 from those used as of December 31, 2013. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the three months ended March 31, 2014. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:



Recurring Fair Value Measurements	March 31, 2014										December 31, 2013
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	242	$	—		$	242		$	—	$	236	$	—		$	236
Equity securities⁽¹⁾	46		—		—			46			45		—		—			45
Foreign government debt securities	—		21		—			21			—		24		—			24
U.S. government debt securities	—		7		—			7			—		5		—			5
Other⁽²⁾	—		12		—			12			—		11		—			11
Total assets	46		282		—			328			45		276		—			321

Liabilities
Derivative liabilities - NUG contracts⁽³⁾	—		—		(22		)	(22		)	—		—		(28		)	(28		)
Total liabilities	—		—		(22		)	(22		)	—		—		(28		)	(28		)

Net assets (liabilities)⁽⁴⁾	$	46	$	282	$	(22	)	$	306		$	45	$	276	$	(28	)	$	293


⁽¹⁾	NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.


⁽²⁾	Primarily consists of short-term cash investments.


⁽³⁾	NUG contracts are subject to regulatory accounting and do not impact earnings.


⁽⁴⁾	Excludes $1 million as of March 31, 2014 and December 31, 2013, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUGs held by ME and classified as Level 3 in the fair value hierarchy during the periods ended March 31, 2014 and December 31, 2013:



(In millions)	Net Derivative Liability NUG Contracts
January 1, 2013 Balance	$	(34	)
Total unrealized losses included in regulatory assets	(2		)
Settlements	8
December 31, 2013 Balance	(28		)
Total unrealized gains included in regulatory assets	10
Settlements	(4		)
March 31, 2014 Balance	$	(22	)

Level 3 Quantitative Information

The following table provides quantitative information for NUG contracts held by ME that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

Fair Value, Net (In millions)

Valuation

Technique

Significant Input

Range

Weighted Average

Units

NUG Contracts

(22

)

Model

Generation
Electricity regional prices

592 to 604,000

$47.66 to $58.78

148,206

$54.39

MWH

Dollars/MWH

INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include AFS securities.

The NDT is subject to regulatory accounting, and therefore, net unrealized gains and losses are recorded as regulatory assets or liabilities because the difference between investments held in the trust and the decommissioning liabilities is expected to be recovered from or refunded to customers.

The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.

AFS Securities

ME holds debt and equity securities within its NDT trust. These trust investments are considered AFS securities recognized at fair market value. ME has no securities held for trading purposes.

The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT trusts as of March 31, 2014 and December 31, 2013:



	March 31, 2014⁽¹⁾						December 31, 2013⁽¹⁾
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities	$	263	$	7	$	270	$	260	$	5	$	265
Equity securities	$	41	$	5	$	46	$	41	$	4	$	45


⁽¹⁾	Excludes short-term cash investments of $13 million and $12 million as of March 31, 2014 and December 31, 2013, respectively.

Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2014 and 2013 were as follows:



Three Months Ended	Sale Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
March 31, 2014	$	54	$	2	$	(3	)	$	3
March 31, 2013	$	57	$	—	$	(1	)	$	3

LONG-TERM DEBT

The following table provides the approximate fair value and related carrying amounts of long-term debt, excluding capital lease obligations and net unamortized premiums and discounts as of March 31, 2014 and December 31, 2013.



	March 31, 2014				December 31, 2013
(In millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt	$	779	$	827	$	779	$	827

The fair values of long-term debt reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of ME. ME classified long-term debt as Level 2 in the fair value hierarchy as of March 31, 2014 and December 31, 2013.

On April 1, 2014, ME repurchased approximately $29 million of PCRBs which were subject to a mandatory put on such date. ME is currently holding the PCRB's for remarketing subject to future market and other conditions.

6. DERIVATIVE INSTRUMENTS

ME is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FE’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FE, including ME. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice.

NUG contracts are reflected on the Balance Sheets at fair value on a gross basis and have not been designated in a hedging relationship. The portfolio of NUG contracts does not allow for the offsetting of derivative assets and derivative liabilities. Changes in the fair value of NUG contracts are recorded as regulatory assets or liabilities. ME held no other derivative assets or liabilities as of March 31, 2014 or December 31, 2013. ME performs qualitative analyses to determine whether a variable interest gives ME a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity's economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. None of the NUG contracts qualify as a VIE.

ME had NUG liabilities of $22 million and $28 million in power purchase contract liabilities on its consolidated Balance Sheets as of March 31, 2014 and December 31, 2013, respectively. None of the counterparties to these contracts require collateral to mitigate credit exposure. ME is expected to purchase 1 million MWHs of power associated with its NUG contracts in future periods.

Unrealized gains on ME's NUG contracts for the three months ended March 31, 2014 and 2013 were $10 million and $4 million, respectively, which are subject to regulatory accounting and did not impact earnings.

7. REGULATORY MATTERS

PENNSYLVANIA

ME currently operates under a DSP that expires on May 31, 2015, and provides for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On November 4, 2013, the Pennsylvania Companies filed DSPs that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for

quarterly descending clock auctions to procure 3-, 12-, 24-, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure SRECs for ME, PN, and Penn. The Pennsylvania Companies’ have reached a settlement with all parties on all issues raised in the cases with the exception of the treatment of NITS charges. On May 6, 2014, the ALJ issued a Recommended Decision recommending adoption of the settlement without modification and the denial of several parties' request for non-bypassable treatment of NITS charges. On May 27, 2014, ME, Penelec, and several other parties filed exceptions to the May 6 Recommended Decision. A final order is expected from the PPUC by August 2014.

The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN refunded those amounts to customers over a 29-month period that began in January 2011. On appeal, the Commonwealth Court affirmed the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME's and PN's TSC riders. The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari. ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania to obtain an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges. On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a pre-tax regulatory asset impairment charge of approximately $254 million (ME - $189 million) in the quarter ended September 30, 2013. The balance of marginal transmission losses was fully refunded to customers by June 30, 2013. On October 29, 2013, ME and PN filed a Notice of Appeal of the U.S. District Court's decision to dismiss the complaint with the United States Court of Appeals for the Third Circuit. Oral argument was held on April 8, 2014, and, at the end of the argument, the Third Circuit directed ME and PN, and the PPUC, each to submit a brief on April 16, 2014 on the question of whether it is possible to waive the preemptive effect of FERC’s classification of line loss charges as transmission charges. On April 16, 2014, ME and PN, the PPUC, and the Pennsylvania Industrials each submitted briefs on the Third Circuit's questions.

Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed on utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies each submitted a report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME achieved its 2011 benchmarks. On November 15, 2013, the Pennsylvania Companies submitted their energy efficiency and peak demand reduction reports for the period ending May 31, 2013, in which they indicated that all of the Pennsylvania Companies met their statutory requirements. On March 20, 2014, the PPUC issued an Order initially determining that ME, PN and Penn achieved the 2011 and 2013 statutory energy efficiency benchmarks.

Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs. The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016. The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator. Based upon information received, the PPUC has not included a peak demand reduction requirement in the Phase II plans.The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012. On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue. The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps. On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement. Total costs of these plans are expected to be approximately $234 million (ME - $75 million). All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders. The remaining issue, raised by certain natural gas companies, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances. On March 14, 2013, the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies’, adopting the settlement, and rejecting the natural gas companies recommendations.

In addition, Act 129 required utilities to file a SMIP with the PPUC. On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan. The Deployment Plan requested deployment of approximately 98.5% of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about $1.25 billion. Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C. Evidentiary hearings were held and briefs were submitted by the Pennsylvania Companies and the OCA. On November 8, 2013, the ALJ issued a Recommended Decision recommending that the Pennsylvania Companies' Deployment Plan be adopted with certain modifications, including, among other things, that the Pennsylvania Companies perform further benchmarking analyses on their costs and hire an independent consultant to perform further analyses on potential savings. On December 2, 2013, the Pennsylvania Companies submitted exceptions in which they challenged, among other things, certain recommendations in the ALJ's decision, and requested approval of a modification to the deployment schedule so as to allow the

entire smart meter system (170,000 meters) to be built by the end of 2015, instead of the original proposed installation of 60,000 meters by the end of 2016. The OCA took exception to one issue and both the OCA and the Pennsylvania Companies filed replies to exceptions on December 12, 2013. In its March 6, 2014 Opinion and Order, the PPUC rejected the OCA's exception and many of the ALJ's recommendations, including the recommendation to hire an independent consultant and the disallowance of $5.1 million of CIS costs, and affirmed the ALJ's recommendation on the accounting treatment for legacy meter costs. The PPUC also directed the Pennsylvania Companies to file an amendment to the Deployment Plan within thirty days of the Order with sufficient supporting documentation for proper evaluation if the Pennsylvania Companies intend to pursue an accelerated deployment schedule, and the PPUC indicated that it would establish an expedited procedural schedule and rule on the filing within 90 days of the March 6, 2014 Order. The Pennsylvania Companies filed an amended Deployment Plan on March 19, 2014. On March 31, 2014, the OCA filed exceptions to the Pennsylvania Companies amended Deployment Plan arguing: 1) that the amended plan failed to list certain potential cost savings categories that are to be considered by the Pennsylvania Companies; and 2) that the filing of the amended Deployment Plan failed to follow proper procedure. On April 7, 2014, the Pennsylvania Companies filed a reply to the OCA’s exceptions explaining why they should be rejected. A prehearing conference was held on April 25, 2014, and a procedural schedule was established that is expected to allow the PPUC to issue an order by June 5, 2014.

In the PPUC Order approving the FirstEnergy and AE merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania to investigate both intermediate and long-term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the upcoming expiration of the DSPs on May 31, 2015. A final order was issued on February 15, 2013, providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items. Subsequently, the PPUC established five workgroups and one comment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electricity market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by the Pennsylvania Companies and FE on March 27, 2012. If implemented these rules could require a significant change in the ways FE and the Pennsylvania Companies do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition. Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on the proposed rulemaking on April 26, 2012, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them. The House Consumer Affairs Committee of the Pennsylvania General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified. On March 24, 2014, the PPUC issued a letter withdrawing the Proposed Rulemaking.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on ME. NERC is the ERO designated by FERC under Section 215 of the FPA to establish and enforce these reliability standards. NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of ME's facilities are located within the RFC region. ME actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its assets and operations in response to the ongoing development, implementation and enforcement of the reliability standards.

ME believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive systems and facilities, ME may occasionally learn of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, ME will develop information about the item and a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. NERC and FERC continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on ME's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

FERC MATTERS

PJM Transmission Rates

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities. While FirstEnergy and other parties advocated for a traditional "beneficiary pays" approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. On August 6, 2009, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new 500 kV and higher voltage facilities on a load‑ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identified nine separate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high-voltage transmission facilities on a beneficiary pays basis results in certain transmission customers in PJM bearing the majority of the costs. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load-ratio share basis. On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp (or socialized) rate based on the amount of load served in a transmission zone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order and on March 22, 2013, FERC denied rehearing. On March 29, 2013, FirstEnergy filed a Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court for briefing and disposition. Briefing is complete, oral argument was held on April 22, 2014, and a decision is expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order. To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of 50% beneficiary pays and 50% postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing. On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing. On March 22, 2013, FERC granted final acceptance of the hybrid method. Certain parties sought rehearing of parts of FERC's March 22, 2013 order. On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP region. These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region. On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000. On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings. The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC. On January 16, 2014, FERC issued an order regarding the effective date of PJM's separate Order No. 1000 regional transmission planning and cost allocation compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order. On May 15, 2014, FERC again accepted the hybrid cost allocation method for RTEP projects and denied the PUCO’s request for rehearing of that aspect of FERC’s March 2013 order. FERC also denied various other parties’ requests for rehearing of various other aspects of the March 2013 order, but granted rehearing of an aspect of its Order No. 1000 directive that public utility transmission providers remove from their FERC-jurisdictional tariffs and agreements federal rights of first refusal for incumbent transmission providers to construct certain transmission projects, which will allow PJM to consider state law rights of first refusal in transmission planning.

Numerous parties, including ME, sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit. Briefing is complete and oral argument was held on March 20, 2014. In addition, on May 27, 2014, certain FirstEnergy companies, including ME, sought judicial review before the D.C. Circuit of FERC’s March 22, 2013 and May 15, 2014 orders.

The outcome of these proceedings and their impact, if any, on ME cannot be predicted at this time.

Market-Based Rate Authority, Triennial Update

ME has authority from FERC to sell electricity at market-based rates. One condition for retaining this authority is that every three years ME must file an update with the FERC that demonstrates that ME continues to meet FERC’s requirements for holding market-based rate authority. On December 20, 2013, FESC submitted to FERC the most recent triennial market power analysis filing for ME for the current cycle of this filing requirement. That filing is pending before FERC.

8. COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS

Prior to November 1999, ME owned and operated electric generation facilities in Pennsylvania. In response to federal and state deregulation initiatives, it separated its electric generation business from its transmission and distribution businesses by transferring all of its generation assets to an affiliate. However, ME retained responsibility for certain liabilities and obligations arising under environmental laws up to the date of transfer. As more fully discussed below, as an historic owner and operator of generation facilities, ME has been subject to claims alleging violations of environmental law and could have exposure for fines and penalties.

CAA Compliance

In January 2009, the EPA issued an NOV to GenOn Energy, Inc. alleging NSR violations at the Portland coal-fired plant based on “modifications” dating back to the mid-1980's. ME, as a former owner and operator of the Portland Station is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

OTHER LEGAL PROCEEDINGS

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to ME's normal business operations pending against ME. The loss or range of loss in these matters is not expected to be material to ME. The other potentially material items not otherwise discussed above are described under Note 7, Regulatory Matters of the Notes to Financial Statements (Unaudited).

ME accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where ME determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that ME has legal liability or is otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on ME's financial condition, results of operations and cash flows.

Attached files

Stock widget

Investing forum

FIRSTENERGY CORP Reports